1. Field of the Invention
The present invention relates generally to drill string telemetry. More specifically, the invention relates to wired drill pipe telemetry systems and techniques for transmitting signals through a drillstring.
2. Related Art
Downhole systems, such as Measurement While Drilling (MWD) and Logging While Drilling (LWD) systems, derive much of their value from their abilities to provide real-time information about borehole conditions and/or sub-surface formation properties. These downhole measurements may be used to make decisions during the drilling process or to take advantage of sophisticated drilling techniques, such as geosteering. These techniques rely heavily on instantaneous knowledge of the wellbore and surrounding formation that is being drilled. Therefore, it is important to be able to send large amounts of data from the MWD/LWD tool to the surface and to send commands from the MWD/LWD tools to the surface with a minimum time delay. A number of telemetry techniques have been developed for such communications, including wired drill pipe (WDP) telemetry.
The concept of placing a conductive wire in a drill string has been around for some time. For example, U.S. Pat. No. 4,126,848 issued to Denison discloses a drill string telemeter system, wherein a wireline is used to transmit the information from the bottom of the borehole to an intermediate position in the drill string, and a special drilling string, having an insulated electrical conductor and employing ring-shaped electrical contact connectors, as described in U.S. Pat. No. 3,696,332 issued to Dickson, Jr. et al., is used to transmit the information from the intermediate position to the surface. Russian Federation Patent No. RU 2,140,537C1 to Basarygin et al. similarly discloses a hybrid telemetry drill string system having a lower wireline system serially connected to an upper WDP system.
U.S. Pat. No. 3,957,118 issued to Barry et al. discloses a releasable cable and latch system for drill string telemetry in drill pipe joints that are not otherwise wired. U.S. Pat. No. 3,807,502 issued to Heilhecker et al., and U.S. Pat. Nos. 4,806,928 and 4,901,069 to Veneruso similarly disclose methods and apparatus for installing an electrical conductor (i.e., a cable) in a drill string having conventional, non-wired drill pipe.
U.S. Pat. No. 2,379,800 to Hare, European Patent Application No. 399,987 to Wellhausen, and Russian Federation Patent No. 2,040,691 to Konovalov et al. all describe signal transmission systems that employ inductive couplings with WDP. International Patent Application No. WO 02/06716 to Hall et al. also discloses a system for transmitting data through a string of WDP joints using inductive couplers.
For downhole drilling operations, a large number of drill pipe joints are used to form a chain between the surface kelly joint (or, alternatively, the power swivel in top-drive drilling) and a drill bit. This chain of drill pipe joints substantially makes up the body of a drill string (although a drill string includes other components such as MWD tools, LWD tools, drill collars, stabilizers, bent sub, mud motor, bit box, and drill bit). A 15,000 ft (5472 m) well will typically have 500 drill pipe joints each having a length of 30 ft (9.14 m). In WDP operations, some or all of the drill pipe joints may be provided especially by embedding within their walls with conductive wires to form wired drill pipe (“WDP”) joints that are interconnected to provide a communication link between the surface and the drilling tool. With 500 drill pipe joints, also known simply as “pipes” or “tubes,” there are 1000 pipe ends/shoulders to be “made up” or connected by threaded rotation to other pipe joints, tubes, subs, etc. (collectively, “tubular members”). Each of these pipe ends may include communication couplers such as inductive couplers, particularly toroidal transformers.
The sheer number of connections in a drill string raises concerns of reliability for a WDP system. A commercial drilling system is expected to have a minimum mean time between system failures (MTBF) of about 500 hours or more. If one of the wired connections in a WDP system fails, then that communication link fails, whereby the entire telemetry system fails. Therefore, where there are 500 WDP joints in a 15,000 ft (5472 m) well, each WDP should have an MTBF of at least about 250,000 hr (28.5 yr) in order for the entire system to have an MTBF of 500 hr. This means that each WDP joint should have a failure rate of less than 4×10−6 per hr. This requirement is beyond the current WDP technology. Therefore, it is desirable, if not essential, to preemptively address the probability of failures in a WDP system.
Accordingly, it is desirable to possess a telemetry system capable of bypassing WDP-related failures.
It is further desirable to possess a telemetry system that employs WDP technology to advantage, in cooperation with non-wired drill string sections (e.g., non-wired drill pipe), particularly when such non-wired drill string section(s) are already in use.
It is further desirable to have a telemetry system capable of wireless communication at or near the surface to decrease the reliance upon wired systems in the upper portion of the drill string.